An annual emissions factor says very little about the coldest mornings of the year, and those are the hours when an electrified building leans hardest on the grid. Companies swapping boilers for heat pumps are now planning around exactly that gap, while the rules for counting it are being rewritten.
Emissions from purchased electricity fall under Scope 2. Most companies report them twice, once with the local grid's average emissions and once with the contracts and certificates they have bought. Both versions usually rest on annual or monthly figures. Last fall the Greenhouse Gas Protocol, the standard most corporate inventories follow, proposed tying market-based claims to the hour the electricity is used, and the pushback it received has slowed that change considerably.
During the late-January cold snap, petroleum became the New England's main source of electricity around midday on January 24 and stayed on top until early on January 26, the U.S. Energy Information Administration (EIA) reported. Oil-fired output reached almost 8 gigawatts (GW) between January 25 and 26.
Much of that oil burned in gas plants. Almost 41% of New England's 15.1 GW of gas-fired capacity can switch to distillate fuel oil, and operators make the switch when gas is too costly or unavailable, including when supplies are contracted to home heating first. Heating demand and power generation were drawing on the same gas at the same moment. A building that has traded its gas boiler for electric heat ends up on the other side of that competition, pulling electricity in the hours when the grid is reaching for oil.
EIA publishes hourly estimates of the carbon intensity of consumed electricity for each region in its Hourly Electric Grid Monitor, so a company can look up how its own grid behaved through a cold spell. Those figures are averages. They spread a region's emissions across all the electricity used in a given hour, which is a different question from how much a single added heat pump changed what plants ran. Neither one day of data nor one storm settles a heating system's climate performance over a full year.
The GHG Protocol's Scope 2 consultation ran from October 20, 2025, to January 31, 2026, after an extension. It proposed an hourly matching and deliverability requirement for market-based reporting, softened by exemption thresholds, the option of using load profiles to approximate hourly data, a legacy clause for existing contracts and a phased start.
Respondents pushed back. Nearly 1,100 responses arrived from 56 countries, and the GHG Protocol's summary of feedback reports low overall support for both hourly matching and deliverability, lowest among companies and industry groups. Greenhouse gas reporting programs and data providers were more supportive, and nongovernmental organizations and academics were split. In July, the body's Independent Standards Board asked for further work on several market-based reporting approaches.
Its timeline stretched as well. On July 29, the GHG Protocol announced it would merge its corporate standards with ISO 14064-1 into a single global standard. A consolidated draft, including revised Scope 2 rules, is expected for public consultation around the second quarter of 2027, with publication estimated for the fourth quarter of 2028. Hourly matching is still a proposal under review, and no company is bound by it today.
None of this makes electrification a bad bet. Heat pumps move heat instead of making it, so they can deliver several units of heat for each unit of electricity, although output falls as outdoor temperatures drop. A dirtier grid on a cold morning does not by itself erase that advantage. What decides the outcome is how the system performs in the worst hours and what runs alongside it.
The Department of Energy's guidance on electrifying large commercial buildings with boilers notes that projects may need auxiliary electric boilers or resistance heat to cover extreme cold. Some buildings also keep a fossil fuel boiler for peak days. Each of those choices changes energy use, peak demand and the emissions calculation in the very hours that matter. Operating curves that include defrost cycles and backup heat give a far more honest picture than a rated efficiency does. Many of the cost and grid questions around building electrification come down to these same few hundred hours a year.
Procurement needs the same treatment. A yearly block of renewable energy certificates does not show that clean power was generated on a particular January morning. Suppliers can be asked what interval data, generation timestamps and location detail they are able to provide, and the answers are worth weighing against the terms of any power purchase agreement (PPA) under negotiation.
Plenty of the tools for those hours are already in existing buildings, and the starting point for decarbonization is rarely zero. Better insulation, smarter controls, thermal storage and demand response can each trim a building's draw when the grid is expensive and carbon-heavy. Claiming an emissions benefit from them takes a method that counts storage losses and the effect of moving load to other times.
Hourly grid data is already public and getting easier to use, while the standard that may require it is at least two years from final. Equipment selected this winter will still be running when the consolidated standard lands in 2028 and for years beyond. Companies that size heat pumps, backup heat and electricity contracts against their coldest hours now will have that data in hand whichever reporting approach the GHG Protocol settles on.
